Epoxy resin formulations containing an impact modifier for use in subterranean wells

ABSTRACT

A fluid composition comprising: (A) a liquid hardenable resin component comprising an epoxy resin; (B) a hardening agent component comprising a hardening agent for the epoxy resin; (C) an impact modifier component comprising an impact modifier selected to impart an increased impact resistance after hardening of the epoxy resin. A method of treating a treatment zone of a well, the method comprising: introducing the treatment fluid into a well bore; and allowing the treatment fluid to form a hardened mass the well bore.

CROSS-REFERENCE TO RELATED APPLICATIONS

Not applicable.

TECHNICAL FIELD

The disclosure is in the field of producing crude oil or natural gasfrom subterranean formations. More particularly, the present disclosurerelates to methods for servicing wellbores with hardenable resincompositions.

BACKGROUND

Natural resources such as gas, oil, and water residing in a subterraneanformation or zone are usually produced by drilling a well bore into thesubterranean formation while circulating a drilling fluid in the wellbore.

After a portion of the wellbore is drilled, sections of steel pipe,referred to as casing, which are slightly smaller in diameter than theborehole, are placed in at least the uppermost portions of the wellbore.The casing provides structural integrity to the newly drilled borehole.

Cementing is a common well operation. For example, hydraulic cementcompositions can be used in cementing operations in which a string ofpipe, such as casing or liner, is cemented in a wellbore. The cementstabilizes the pipe in the wellbore and prevents undesirable migrationof fluids along the annulus between the wellbore and the outside of thecasing or liner from one zone along the wellbore to the next. Where thewellbore penetrates into a hydrocarbon-bearing zone of a subterraneanformation, the casing can later be perforated to allow fluidcommunication between the zone and the wellbore. The cemented casingalso enables subsequent or remedial separation or isolation of one ormore production zones of the wellbore by using downhole tools, such aspackers or plugs, or by using other techniques, such as forming sandplugs or placing cement in the perforations.

Secondary or remedial cementing operations may also be performed, forexample, to repair a primary cementing or treat conditions within thewell bore after the well bore has been constructed.

A variety of treatment fluids, including non-cementitious sealants, suchas polymer-based, resin-based, or latex-based sealants, have been usedin these secondary or remedial cementing operations. These compositionsmay be introduced and circulated through the well bore to plug a void orcrack in the conduit or cement sheath or an opening between the two.

In addition, such non-cementitious sealants may have other uses orapplications in a well.

GENERAL DESCRIPTION OF EMBODIMENTS

In an embodiment of the present disclosure, a fluid composition isprovided, the fluid composition comprising: (A) an epoxy resin; (B) ahardening agent for the epoxy resin; and (C) an impact modifier selectedto impart an increased impact resistance after hardening of the epoxyresin.

In an embodiment of the present disclosure, a fluid composition isprovided, the fluid composition comprising: (A) a liquid hardenableresin component comprising an epoxy resin; (B) a hardening agentcomponent comprising a hardening agent for the epoxy resin; and (C) animpact modifier component comprising an impact modifier selected toimpart an increased impact resistance after hardening of the epoxyresin.

In another embodiment, a method of servicing a well bore is provided,the method comprising: introducing the treatment fluid into a well bore;and allowing the treatment fluid to form a hardened mass in the wellbore.

These and other embodiments of the disclosure will be apparent to oneskilled in the art upon reading the following detailed description.While the disclosure is susceptible to various modifications andalternative forms, specific embodiments thereof will be described indetail and shown by way of example. It should be understood, however,that it is not intended to limit the disclosure to the particular formsdisclosed.

BRIEF DESCRIPTION OF THE DRAWING

The accompanying drawing is incorporated into the specification to helpillustrate examples according to a presently preferred embodiment of thedisclosure.

FIG. 1 is a graph showing compression testing of an epoxy resinFormulation #1 and a modified epoxy resin Formulation #2, wherein themodified Formulation #2 includes polyethyleneglycol diglycidyl ether(“PEGDGE”).

DETAILED DESCRIPTION OF PRESENTLY PREFERRED EMBODIMENTS AND BEST MODEDefinitions and Usages

General Interpretation

The words or terms used herein have their plain, ordinary meaning in thefield of this disclosure, except to the extent explicitly and clearlydefined in this disclosure or unless the specific context otherwiserequires a different meaning.

The words “comprising,” “containing,” “including,” “having,” and allgrammatical variations thereof are intended to have an open,non-limiting meaning. For example, a composition comprising a componentdoes not exclude it from having additional components, an apparatuscomprising a part does not exclude it from having additional parts, anda method having a step does not exclude it having additional steps. Whensuch terms are used, the compositions, apparatuses, and methods that“consist essentially of” or “consist of” the specified components,parts, and steps are specifically included and disclosed. As usedherein, the words “consisting essentially of,” and all grammaticalvariations thereof are intended to limit the scope of a claim to thespecified materials or steps and those that do not materially affect thebasic and novel characteristic(s) of the claimed disclosure.

The indefinite articles “a” or “an” mean one or more than one of thecomponent, part, or step that the article introduces.

Whenever a numerical range of degree or measurement with a lower limitand an upper limit is disclosed, any number and any range falling withinthe range is also intended to be specifically disclosed. For example,every range of values (in the form “from a to b,” or “from about a toabout b,” or “from about a to b,” “from approximately a to b,” and anysimilar expressions, where “a” and “b” represent numerical values ofdegree or measurement) is to be understood to set forth every number andrange encompassed within the broader range of values.

Oil and Gas Reservoirs

In the context of production from a well, “oil” and “gas” are understoodto refer to crude oil and natural gas, respectively. Oil and gas arenaturally occurring hydrocarbons in certain subterranean formations.

A “subterranean formation” is a body of rock that has sufficientlydistinctive characteristics and is sufficiently continuous forgeologists to describe, map, and name it.

A subterranean formation having a sufficient porosity and permeabilityto store and transmit fluids is sometimes referred to as a “reservoir.”

A subterranean formation containing oil or gas may be located under landor under the seabed off shore. Oil and gas reservoirs are typicallylocated in the range of a few hundred feet (shallow reservoirs) to a fewtens of thousands of feet (ultra-deep reservoirs) below the surface ofthe land or seabed.

Well Servicing and Fluids

Generally, well services include a wide variety of operations that maybe performed in oil, gas, geothermal, chemical disposal, or water wells,such as drilling, cementing, completion, and intervention. Well servicesare designed to facilitate or enhance the production of desirable fluidssuch as oil or gas from or through a subterranean formation. A wellservice usually involves introducing a fluid into a well.

A “well” includes a wellhead and at least one wellbore from the wellheadpenetrating the earth. The “wellhead” is the surface termination of awellbore, which surface may be on land or on a seabed.

A “well site” is the geographical location of a wellhead of a well. Itmay include related facilities, such as a tank battery, separators,compressor stations, heating or other equipment, and fluid pits. Ifoffshore, a well site can include a platform.

The “wellbore” refers to the drilled hole, including any cased oruncased portions of the well or any other tubulars in the well. The“borehole” usually refers to the inside wellbore wall, that is, the rocksurface or wall that bounds the drilled hole. A wellbore can haveportions that are vertical, horizontal, or anything in between, and itcan have portions that are straight, curved, or branched. As usedherein, “uphole,” “downhole,” and similar terms are relative to thedirection of the wellhead, regardless of whether a wellbore portion isvertical or horizontal.

As used herein, introducing “into a well” means introducing at leastinto and through the wellhead. According to various techniques known inthe art, tubulars, equipment, tools, or fluids can be directed from thewellhead into any desired portion of the wellbore.

As used herein, the word “tubular” means any kind of structural body inthe general form of a tube. Tubulars can be of any suitable bodymaterial, but in the oilfield they are most commonly of steel. Examplesof tubulars in oil wells include, but are not limited to, a drill pipe,a casing, a tubing string, a line pipe, and a transportation pipe.

As used herein, the term “annulus” means the space between two generallycylindrical objects, one inside the other. The objects can be concentricor eccentric. Without limitation, one of the objects can be a tubularand the other object can be an enclosed conduit. The enclosed conduitcan be a wellbore or borehole or it can be another tubular. Thefollowing are some non-limiting examples illustrating some situations inwhich an annulus can exist. Referring to an oil, gas, or water well, inan open hole well, the space between the outside of a tubing string andthe borehole of the wellbore is an annulus. In a cased hole, the spacebetween the outside of the casing and the borehole is an annulus. Inaddition, in a cased hole there may be an annulus between the outsidecylindrical portion of a tubular, such as a production tubing string,and the inside cylindrical portion of the casing. An annulus can be aspace through which a fluid can flow or it can be filled with a materialor object that blocks fluid flow, such as a packing element. Unlessotherwise clear from the context, as used herein an “annulus” is a spacethrough which a fluid can flow.

As used herein, the word “treatment” refers to any treatment forchanging a condition of a portion of a wellbore or a subterraneanformation adjacent a wellbore; however, the word “treatment” does notnecessarily imply any particular treatment purpose. A treatment usuallyinvolves introducing a fluid for the treatment, in which case it may bereferred to as a treatment fluid, into a well. As used herein, a“treatment fluid” is a fluid used in a treatment. The word “treatment”in the term “treatment fluid” does not necessarily imply any particulartreatment or action by the fluid.

In the context of a well or wellbore, a “portion” or “interval” refersto any downhole portion or interval along the length of a wellbore.

A “zone” refers to an interval of rock along a wellbore that isdifferentiated from uphole and downhole zones based on hydrocarboncontent or other features, such as permeability, composition,perforations or other fluid communication with the wellbore, faults, orfractures. A zone of a wellbore that penetrates a hydrocarbon-bearingzone that is capable of producing hydrocarbon is referred to as a“production zone.” A “treatment zone” refers to an interval of rockalong a wellbore into which a fluid is directed to flow from thewellbore. As used herein, “into a treatment zone” means into and throughthe wellhead and, additionally, through the wellbore and into thetreatment zone.

Generally, the greater the depth of the formation the higher the statictemperature and pressure of the formation. Initially, the staticpressure equals the initial pressure in the formation before production.After production begins, the static pressure approaches the averagereservoir pressure.

A “design” refers to the estimate or measure of one or more parametersplanned or expected for a particular fluid or stage of a well service ortreatment. For example, a fluid can be designed to have components thatprovide a minimum density or viscosity for at least a specified timeunder expected downhole conditions. A well service may include designparameters such as fluid volume to be pumped, required pumping time fora treatment, or the shear conditions of the pumping.

The term “design temperature” refers to an estimate or measurement ofthe actual temperature at the downhole environment during the time of atreatment. For example, the design temperature for a well treatmenttakes into account not only the bottom hole static temperature (“BHST”),but also the effect of the temperature of the fluid on the BHST duringtreatment. The design temperature for a fluid is sometimes referred toas the bottom hole circulation temperature (“BHCT”). Because fluids maybe considerably cooler than BHST, the difference between the twotemperatures can be quite large. Ultimately, if left undisturbed asubterranean formation will return to the BHST.

Chemical Polymers and Derivatives

As used herein, unless the context otherwise requires, a “polymer” or“polymeric material” can include one or more homopolymers, copolymers,terpolymers, etc. In addition, the term “copolymer” as used herein isnot limited to the combination of polymers having two monomeric units,but includes any combination of monomeric units, for example,terpolymers, tetrapolymers, etc.

As used herein, “modified” or “derivative” means a chemical compoundformed by a chemical process from a parent compound, wherein thechemical backbone skeleton of the parent compound is retained in thederivative. The chemical process preferably includes at most a fewchemical reaction steps, and more preferably only one or two chemicalreaction steps. As used herein, a “chemical reaction step” is a chemicalreaction between two chemical reactant species to produce at least onechemically different species from the reactants (regardless of thenumber of transient chemical species that may be formed during thereaction). An example of a chemical step is a substitution reaction.Substitution on the reactive sites of a polymeric material may bepartial or complete.

Phases and Physical States

As used herein, “phase” is used to refer to a substance having achemical composition and physical state that is distinguishable from anadjacent phase of a substance having a different chemical composition ora different physical state.

The word “material” refers to the substance, constituted of one or morephases, of a physical entity or object. Rock, water, air, metal, sand,wood, and cement are all examples of materials.

As used herein, if not other otherwise specifically stated, the physicalstate or phase of a substance (or mixture of substances) and otherphysical properties are determined at a temperature of 77° F. (25° C.)and a pressure of 1 atmosphere (Standard Laboratory Conditions) withoutapplied shear.

Dispersions

A dispersion is a system in which particles of a substance of onechemical composition and physical state are dispersed in anothersubstance of a different chemical composition or physical state. Inaddition, phases can be nested. If a substance has more than one phase,the most external phase is referred to as the continuous phase of thesubstance as a whole, regardless of the number of different internalphases or nested phases.

Fluids

A fluid can be a homogeneous or heterogeneous. In general, a fluid is anamorphous substance that is or has a continuous phase of particles thatare smaller than about 1 micrometer that tends to flow and to conform tothe outline of its container.

Every fluid inherently has at least a continuous phase. A fluid can havemore than one phase. The continuous phase of a treatment fluid is aliquid under Standard Laboratory Conditions.

Apparent Viscosity of a Fluid

Viscosity is a measure of the resistance of a fluid to flow. In everydayterms, viscosity is “thickness” or “internal friction.” Therefore, purewater is “thin,” having a relatively low viscosity whereas honey is“thick,” having a relatively higher viscosity. Put simply, the lessviscous the fluid is, the greater its ease of movement (fluidity). Moreprecisely, viscosity is defined as the ratio of shear stress to shearrate.

Setting, Setting Materials, and Setting Compositions

As used herein, the term “set” means the process of becoming a solid bycuring.

As used herein, a “setting material” or “setting composition” is amaterial or composition that sets.

Depending on the composition and the conditions, it can take just a fewminutes up to days or longer for some setting compositions to set.

Compressive strength is defined as the capacity of a material towithstand axially directed pushing forces. The compressive strength asetting composition attains is a function of both curing time andtemperature, among other things.

General Approach

A purpose of this disclosure is to significantly improve the impactresistance of epoxy thermoset polymer resin systems after hardening,specifically the impact resistance at low temperatures.

Epoxy thermoset polymer resin systems exhibit high compressive strengthand can tolerate high compressive strains without failure. As usedherein, high compressive strength means at least 1,000 psi, for example,in the range of about 1,000 psi to about 20,000 psi.

However, at low temperatures current epoxy resin formulations aresusceptible to fracture when subjected to a sudden impact, for example,when struck with a high concentrated force, similar to hitting with ahammer. Impact resistance can be particularly important at a lowtemperature in the range of about 50° F. to about 80° F. Improvement ofimpact properties is particularly valuable for offshore applications,particularly near the mudline in deepwater. The “mudline” is the seabottom, that is, the interface between the water and the earth.“Deepwater” is normally considered to be water more than 500 feet deep.

In various embodiments of the present, the composition for a treatmentfluid comprises a liquid hardenable resin component, a hardening agentcomponent, and an impact modifier component.

Such compositions can be useful in relatively cold temperature wellenvironments, providing enhanced durability and impact resistance incold environments, such as deepwater environments or those near themudline where low temperatures are often experienced.

Such compositions can be used in various well operations, such assqueeze cementing operations, primary isolation in chemical disposalwells, and plug and abandonment. In addition, such compositions can beuseful in the formation of secondary barriers in a well. For example,such compositions can be useful in forming a sheath in an annular spacein a well, such as between two tubular strings, between a casing and aborehole of a well, or in a casing or other tubular to form a plug.

Liquid Hardenable Resin Component

The treatment fluid of the present disclosure includes a liquidhardenable resin component comprising a resin.

Resin

As used herein, the term “resin” refers to any of a number of physicallysimilar polymerized synthetics or chemically modified natural resinsincluding thermoplastic materials and thermosetting materials.

Selection of a suitable resin may be affected by the temperature of thesubterranean formation to which the fluid will be introduced. By way ofexample, for subterranean formations having a bottom hole statictemperature (“BHST”) ranging from about 60° F. to about 250° F.,epoxy-based resin systems may be preferred.

Epoxy resins, also known as polyepoxides, are a class of reactiveprepolymers and polymers which contain epoxide groups. Epoxy resins maybe reacted (that is, cross-linked) either with themselves throughcatalytic homopolymerisation, or with co-reactants such aspolyfunctional amines, carboxylic acids, acid anhydrides, phenols,alcohols, and thiols. These co-reactants are often referred to ashardeners, and the cross-linking reaction is commonly referred to ascuring. Reaction of polyepoxides with themselves or with polyfunctionalhardeners forms a thermosetting polymer, often with strong mechanicalproperties as well as high temperature and chemical resistance

In an embodiment of the disclosed methods, the epoxy resin comprises adiglycidyl ether functionalized molecule or any multifunctional glycidylether molecule. In an embodiment, the diglycidyl ether molecule ispreferably non-polymeric. For example, the diglycidyl ether molecule canbe selected from the group consisting of: a diglycidyl ether ofbisphenol A, optionally blended with butyl glycidyl ether, cyclohexanedimethanol diglycidyl ether, and any combination thereof. In anembodiment, the epoxy resin comprises a novolac epoxy resin.

Solvent or Diluent for Resin

In some embodiments, a solvent or diluent may be added to the resin toreduce its viscosity for ease of handling, mixing, transferring, orpumping.

Generally, any solvent or diluent that is compatible with the hardenableresin and that achieves the desired viscosity effect may be suitable foruse in the liquid hardenable resin component of the well bore servicingfluid. Such solvents may include, but are not limited to, polyethyleneglycols, polyethyleneglycol ethers, butyl lactate, dipropylene glycolmethyl ether, dipropylene glycol dimethyl ether, dimethyl formamide,diethyleneglycol methyl ether, ethyleneglycol butyl ether,diethyleneglycol butyl ether, propylene carbonate, d′limonene, fattyacid methyl esters, isopariffinic fluids, and heavy aromatic fluids, andcombinations thereof. Other solvents may include aqueous dissolvablesolvents such as, methanol, isopropanol, butanol, and glycol ethersolvents, and combinations thereof. Glycol ether solvents include, butare not limited to, diethylene glycol methyl ether, dipropylene glycolmethyl ether, 2-butoxy ethanol, ethers of a C2 to C6 dihydric alkanolcontaining at least one C1 to C6 alkyl group, mono ethers of dihydricalkanols, methoxypropanol, butoxyethanol, and hexoxyethanol, and isomersthereof.

Reactive diluents are often preferred because they cure into the resinnetwork whereas solvents do not. Examples of reactive diluents are alkylglycidyl ethers and phenyl glycidyl ethers.

Selection of an appropriate solvent or diluent may be dependent on theresin composition chosen. With the benefit of this disclosure, theselection of an appropriate solvent should be within the ability of oneskilled in the art. In some embodiments, the amount of the solvent usedin the liquid hardenable resin component may be in the range of about0.1% to about 30% by weight of the liquid hardenable resin component.

However, in particular embodiments, it may be desirable not to use asolvent or diluent for environmental or safety reasons. It is within theability of one skilled in the art with the benefit of this disclosure todetermine if and how much solvent may be needed to achieve a viscositysuitable to the subterranean conditions of a particular application.Factors that may affect this decision include geographic location of thewell, the surrounding weather conditions, and the desired long-termstability of the well bore servicing fluid.

Aqueous Diluent for Resin

In some embodiments, the liquid hardenable resin component may alsocomprise an aqueous diluent or carrier fluid to reduce the viscosity ofthe liquid hardenable resin component.

If the resin is hydrophobic, which is often the case, the resin may bedispersed in an aqueous phase as an emulsion.

The aqueous fluids used in the consolidation fluids of the presentdisclosure may comprise fresh water, saltwater (e.g., water containingone or more salts dissolved therein), brine (for example, saturatedsaltwater), seawater, or combinations thereof, and may be from anysource, provided that they do not contain components that mightadversely affect the stability or performance of the well bore servicingfluid.

In some embodiments, the aqueous diluent or carrier fluid may be presentin the liquid hardenable resin component in an amount from about 0.1% toabout 25% by volume of the liquid hardenable resin component. In otherembodiments, the aqueous diluent or carrier fluid may be present in theliquid hardenable resin component in an amount from about 0.1% to about5% by volume of the liquid hardenable resin component.

Heating to Reduce Viscosity of Resin

Optionally, the liquid hardenable resin component may be heated toreduce its viscosity, in place of, or in addition to, using a diluent,solvent, or carrier liquid.

Concentration of Resin in Liquid Hardenable Resin Component

Generally, the resin can be included in the liquid hardenable resincomponent in an amount in the range of about 5% to about 100% by volumeof the liquid hardenable resin component. In particular embodiments, thehardenable resin may be included in the liquid hardenable resincomponent in an amount of about 75% to about 100% by volume of theliquid hardenable resin component. It is within the ability of oneskilled in the art with the benefit of this disclosure to determine howmuch of the liquid hardenable resin may be needed to achieve the desiredresults. Factors that may affect this decision include the type ofliquid hardenable resin and liquid hardening agent used in a particularapplication.

Concentration of Liquid Hardenable Resin Component in Treatment Fluid

Generally, the liquid hardenable resin component may be included in thetreatment fluid in an amount from about 5% to about 90% by volume of thetreatment fluid. In particular embodiments, the liquid hardenable resincomponent may be included in the treatment fluid in an amount from about50% to about 75% by volume of the treatment fluid.

Hardening Agent Component

The treatment fluid of the present disclosure also includes a liquidhardening agent component comprising a hardening agent. As used herein,“hardening agent” refers to any substance capable of transforming thehardenable resin into a hardened, consolidated mass.

Hardening Agent for Liquid Hardening Agent Component

Common classes of hardeners for epoxy resins include amines, acids, acidanhydrides, phenols, alcohols and thiols.

Examples of hardening agents include, but are not limited to, aliphaticamines, aliphatic tertiary amines, aromatic amines, cycloaliphaticamines, heterocyclic amines, amido amines, polyamides, polyethyl amines,polyether amines, polyoxyalkylene amines, carboxylic anhydrides,carboxylic acids, triethylenetetraamine, ethylene diamine,N-cocoalkyltrimethylene, isophorone diamine, N-aminophenyl piperazine,imidazoline, 1,2-diaminocyclohexane, polytheramine,diethyltoluenediamine, 4,4′-diaminodiphenyl methane,methyltetrahydrophthalic anhydride, hexahydrophthalic anhydride, maleicanhydride, polyazelaic polyanhydride, phthalic anhydride, andcombinations thereof. Commercially available hardening agents mayinclude, but are not limited to, ETHACURE™ 100, available from AlbemarleCorp. of Baton Rouge, La., and JEFFAMINE™ D-230, available from HuntsmanCorp. of The Woodlands, Tex.

Accelerator for Liquid Hardening Agent Component

The epoxy curing reaction may be accelerated by addition of smallconcentrations of one or more accelerators. Some hardening agents arealso considered to be accelerators for the hardening of the resin.

Hardeners are generally primary or secondary amines. Tertiary amines,carboxylic acids and alcohols, (especially phenols) are effectiveaccelerators.

In some embodiments, in particular embodiments, the hardening agent maycomprise a fast-setting hardening agent and a slow-setting hardeningagent. As used herein, “fast-setting hardening agent” and “slow-settinghardening agent” do not imply any specific rate at which the agents seta hardenable resin; instead, the terms merely indicate the relativerates at which the hardening agents initiate hardening of the resin.Whether a particular hardening agent is considered fast-setting orslow-setting may depend on the other hardening agent(s) with which it isused. In a particular embodiment, ETHACURE™ 100 may be used as aslow-setting hardening agent and JEFFAMINE™ D-230, may be used as afast-setting hardening agent. In some embodiments, the ratio offast-setting hardening agent to slow-setting hardening agent may beselected to achieve a desired behavior of liquid hardening agentcomponent. For example, in some embodiments, the fast-setting hardeningagent may be included in the liquid hardening agent component in a ratioof approximately 1:5, by volume, with the slow-setting hardening agent.With the benefit of this disclosure, one of ordinary skill in the artshould be able to select the appropriate ratio of hardening agents foruse in a particular application.

Concentration of Hardener in Liquid Hardening Agent Component

The hardening agent may be included in the liquid hardening agentcomponent in an amount sufficient to at least partially harden the resincomposition. In some embodiments of the present disclosure, thehardening agent used may be included in the liquid hardening agentcomponent in the range of about 5% to about 100% by volume of the liquidhardening agent component. In other embodiments, the hardening agentused may be included in the liquid hardening agent component in anamount of about 50% to about 75% by volume of the liquid hardening agentcomponent.

Optional Silane Coupling Agent for Liquid Hardening Agent Component

The liquid hardening agent component of the treatment fluid may alsoinclude an optional silane coupling agent. The silane coupling agent maybe used, among other things, to act as a mediator to help bond the resinto the surface of the subterranean formation or the surface of the wellbore.

Examples of silane coupling agents include, but are not limited to,N-2-(aminoethyl)-3-aminopropyltrimethoxysilane;3-glycidoxypropyltrimethoxysilane; gamma-aminopropyltriethoxysilane;N-beta-(aminoethyl)-gamma-aminopropyltrimethoxysilanes;aminoethyl-N-beta-(aminoethyl)-gamma-aminopropyl-trimethoxysilanes;gamma-ureidopropyl-triethoxysilanes;beta-(3,4epoxy-cyclohexyl)-ethyl-trimethoxysilane;gamma-glycidoxypropyltrimethoxysilanes; vinyltrichlorosilane; vinyltris(beta-methoxyethoxy) silane; vinyltriethoxysilane;vinyltrimethoxysilane; 3-metacryloxypropyltrimethoxysilane;beta-(3,4epoxycyclohexyl)-ethyltrimethoxysilane;r-glycidoxypropyltrimethoxysilane;r-glycidoxypropylmethylidiethoxysilane;N-beta-(aminoethyl)-r-aminopropyl-trimethoxysilane;N-beta-(aminoethyl)-r-aminopropylmethyldimethoxysilane;3-aminopropyl-triethoxysilane; N-phenyl-r-aminopropyltrimethoxysilane;r-mercaptopropyltrimethoxysilane; r-chloropropyltrimethoxysilane;vinyltrichlorosilane; vinyltris (beta-methoxyethoxy) silane;vinyltrimethoxysilane; r-metacryloxypropyltrimethoxysilane; beta-(3,4epoxycyclohexyl)-ethyltrimethoxysila; r-glycidoxypropyltrimethoxysilane;r-glycidoxypropylmethylidiethoxysilane;N-beta-(aminoethyl)-r-aminopropyltrimethoxysilane;N-beta-(aminoethyl)-r-aminopropylmethyldimethoxysilane;r-aminopropyltriethoxysilane; N-phenyl-r-aminopropyltrimethoxysilane;r-mercaptopropyltrimethoxysilane; r-chloropropyltrimethoxysilane;N[3-(trimethoxysilyl)propyl]-ethylenediamine; substituted silanes whereone or more of the substitutions contains a different functional group;and combinations thereof. Generally, the silane coupling agent may beincluded in the liquid hardening agent component in an amount capable ofsufficiently bonding the resin to the particulate.

Concentration of Silane Coupling Agent in Liquid Hardening AgentComponent

In some embodiments of the present disclosure, the silane coupling agentmay be included in the liquid hardening agent component in the range ofabout 0.1% to about 95% by volume of the liquid hardening agentcomponent. In other embodiments, the fast-setting hardening agent may beincluded in the liquid hardening agent component in an amount of about5% to about 50% by volume of the liquid hardening agent component. Inother embodiments, the fast-setting hardening agent may be included inthe liquid hardening agent component in an amount of about 25% by volumeof the liquid hardening agent component.

Optional Solvent or Diluent for Liquid Hardening Agent Component

An optional diluent or liquid carrier fluid may also be used in theliquid hardening agent component to, among other things, reduce theviscosity of the liquid hardening agent component for ease of handling,mixing, or transferring. However, in some embodiments, it may bedesirable, for environmental or safety reasons, not to use a solvent.

Any suitable carrier fluid that is compatible with the liquid hardeningagent component and achieves the desired viscosity effects may besuitable for use in the present disclosure. Some suitable liquid carrierfluids are those having high flash points (for example, above about 125°F.) because of, among other things, environmental and safety concerns;such solvents may include, but are not limited to, polyethylene glycol,butyl lactate, butylglycidyl ether, dipropylene glycol methyl ether,dipropylene glycol dimethyl ether, dimethyl formamide, diethyleneglycolmethyl ether, ethyleneglycol butyl ether, diethyleneglycol butyl ether,propylene carbonate, d′ limonene, fatty acid methyl esters, andcombinations thereof. In particular embodiments, selection of anappropriate liquid carrier fluid may be dependent on, inter alia, theresin composition chosen.

Concentration of Liquid Hardening Agent Component in Treatment Fluid

Generally, the liquid hardening agent component may be included in thetreatment fluid in an amount from about 1% to about 50% by volume of thetreatment fluid. In particular embodiments, the liquid hardening agentcomponent may be included in the treatment fluid in an amount from about5% to about 25% by volume of the treatment fluid.

In particular embodiments, the amount of liquid hardening agentcomposition may be selected to impart a desired elasticity orcompressibility to a resulting well bore plug. Generally, the lower theamount of hardening agent present in the treatment fluid, the greaterthe elasticity or compressibility of a resulting well bore plug. Withthe benefit of this disclosure, it should be within the skill of one orordinary skill in the art to select an appropriate amount of hardeningagent to achieve a desired elasticity or compressibility for aparticular application.

Impact Modifier Component

The treatment fluid of the present disclosure includes an impactmodifier component comprising an impact modifier. As used herein,“impact modifier” refers to any substance capable of increasing theresistance of a hardened resin composition to sudden impact.

Impact Modifier

Impact resistance can be particularly important at a low temperature inthe range of about 50° F. to about 80° F.

The impact resistance of a resin of can be significantly improved byincorporation of an impact modifier into the resin. When chemicallyreacted into the resin, an impact modifier serves to disperse the energyof impact through the entire system and prevent crack formation due tohighly concentrated impacts and strains.

An impact modifier can be selected from the group consisting of: apolyethyleneglycol or a polypropyleneglycol having a functionalityselected from the group consisting of: glycidyl ether, epoxide,carboxylic acid, and anhydride. In an embodiment, the polyethyleneglycolhas in the range about 2 to about 1,000 monomeric units. The impactmodifier comprise single, double, or multiple functionality.

In an embodiment, the impact modifier can be selected from the groupconsisting of: polyethyleneglycol diglycidyl ether, polypropyleneglycoldiglycidyl ether, and any combination thereof. For example,incorporation polyethyleneglycol diglycidyl ether (“PEGDGE”) into epoxythermoset polymer resin formulations has resulted in substantialimprovements in impact resistance.

Optional Solvent or Diluent for Impact Modifier Component

An optional solvent, diluent, or liquid carrier fluid may also be usedin the impact modifier component to, among other things, reduce theviscosity of the impact modifier component for ease of handling, mixing,or transferring. However, in some embodiments, it may be desirable, forenvironmental or safety reasons, not to use a solvent.

Any suitable carrier fluid that is compatible with the liquid hardeningagent component and achieves the desired viscosity effects may besuitable for use in the present disclosure. Some suitable liquid carrierfluids are those having high flash points (for example, above about 125°F.) because of, among other things, environmental and safety concerns.

Concentration of Impact Modifier in Liquid Impact Modifier Component

The impact modifier may be included in the liquid impact modifiercomponent in an amount sufficient to increase the impact resistance ofthe hardened resin system. In some embodiments of the presentdisclosure, the impact modifier used may be included in the liquidmodifier component in the range of about 5% to about 100% by volume ofthe liquid impact modifier component. In other embodiments, the impactmodifier used may be included in the liquid impact modifier component inan amount of about 50% to about 75% by volume of the liquid impactmodifier component.

Concentration of Impact Modifier Component in Treatment Fluid

Generally, the impact modifier component may be included in thetreatment fluid in an amount from about 1% to about 50% by volume of thetreatment fluid.

Optional Solid Particulate Materials in Composition of Treatment Fluid

In some embodiments of the present disclosure, additional solidparticulate materials may also be included in the treatment fluid toenhance the strength, hardness, and/or toughness of the resulting wellbore plug or sheath. These materials are optional and need not beincluded in treatment fluid for that composition to fall within theteachings of the present disclosure. These solid materials may includeboth natural and man-made materials, and may have any shape, including,but not limited to, beaded, cubic, bar-shaped, cylindrical, or mixturesthereof, and may be in any form including, but not limited to flake orfiber form. Such materials may include, but are not limited to, silica,barite, cellulose fibers, carbon fibers, glass fibers, mineral fibers,plastic fibers (for example, polypropylene and polyacrylic nitrilefibers), metallic fibers, metal shavings, Kevlar fibers, basalt fibers,wollastonite, micas (for example, phlogopites and muscovites), andmixtures thereof.

Carbon fibers suitable for use in particular embodiments of the presentdisclosure include high tensile modulus carbon fibers which have a hightensile strength. In some embodiments, the tensile modulus of the carbonfibers may exceed 180 GPa, and the tensile strength of the carbon fibersmay exceed 3000 MPa. Generally, the fibers may have a mean length ofabout 1 mm or less. In some embodiments, the mean length of the carbonfibers is from about 50 to about 500 microns. In particular embodiment,the carbon fibers have a mean length in the range of from about 100 toabout 200 microns. In particular embodiments, the carbon fibers may bemilled carbon fibers. Commercially available carbon fibers include, butare not limited to, “AGM-94” and “AGM-99” carbon fibers both availablefrom Asbury Graphite Mills, Inc., of Asbury, N.J.

Metallic fibers for use in particular embodiments of the presentdisclosure may include non-amorphous (that is, crystalline) metallicfibers. In particular embodiments, the non-amorphous metallic fibers maybe obtained by cold drawing steel wires (that is, steel wool). Examplesof metallic fibers include, but are not limited to, steel fibers.Generally, the length and diameter of the metallic fibers may beadjusted such that the fibers are flexible and easily dispersible in thetreatment fluid, and the treatment fluid is easily pumpable.

These additional solid materials may be present in the treatment fluidof the present disclosure individually or in combination. Additionally,the solid materials of the present disclosure may be present in thetreatment fluid in a variety of lengths and/or aspect ratios. A personhaving ordinary skill in the art, with the benefit of this disclosure,will recognize the mixtures of type, length, and/or aspect ratio to useto achieve the desired properties of treatment fluid for a particularapplication.

EXAMPLES

To facilitate a better understanding of the present disclosure, thefollowing examples of certain aspects of some embodiments are given. Inno way should the following examples be read to limit, or define, theentire scope of the disclosure.

In an example, two epoxy resin formulations including at least resin,hardener, and accelerator were mixed and allowed to cure, one withoutPEGDGE and the other with PEGDGE, each having the same ratio of epoxidegroups of the glycidyl ether of the resin to hydrogen bonded to nitrogen(“active hydrogen”) of the hardener. This ratio was maintained byadjusting the amount of a hardening agent. The accelerator was alsomaintained at 4 percent by mass of the sum of the other components. Thecompositions of the two epoxy resin formulations are shown in Table 1.

TABLE 1 Epoxy Resin Formulations Component Formulation #1 Formulation #2Resin (diglycidyl ether of bisphenol 450.0 grams 450.0 grams A blendedwith butyl glycidyl ether) Resin (cyclohexane dimethanol 150.0 grams 0.0 grams diglycidyl ether) Hardening Agent 144.6 grams 170.1 grams(diethyltoluenediamine) Accelerator (2,4,6  29.7 grams  30.9 gramstridimethylaminomethylphenol) Impact Modifier (PEGDGE)  0.0 grams   150grams

Nine days after mixing of the formulations, the two specimens of eachhardened sample was evaluated for impact resistance using an impacttester. In the impact testing experiment, a 2 pound weight with arounded point at the end is dropped from a height of 48 inches onto thesample.

As shown in Table 2, no failure was observed in the Formulation #2containing PEGDGE even after 10 repeated impacts, while currentformulations could not withstand one impact. Formulations containingPEGDGE offer significantly improved impact resistance over a formulationwithout PEGDGE.

TABLE 2 Impact testing of Expox Resin Formulations Impact ResultsFormulation #1 Formulation #2 Impact Test #1 1 impact, failure  3impacts, no failure Impact Test #2 1 impact, failure 10 impacts, nofailure

FIG. 1 is a graph showing compression testing of an epoxy resinFormulation #1 and a modified epoxy resin Formulation #2, wherein themodified Formulation #2 includes PEGDGE. The Formulation #2 samplecontaining PEGDGE maintained compressive strength and exhibited aslightly higher strain at failure, while Young's modulus was seen to bereduced. Compressive strength is the stress at failure measured in psi.Compressive strength is measured using a load frame to determine theforce required to crush a sample than dividing by the area in contactwith the sample. Compressive strain is the change in length of thesample divided by the initial length during a compression test.

Method of Treating a Well with the Fluid

According to another embodiment of the disclosure, a method of treatinga well, is provided, the method including the steps of: forming atreatment fluid according to the disclosure; and introducing thetreatment fluid into the well.

Forming Treatment Fluid

A treatment fluid according to the disclosure can be prepared at the jobsite, prepared at a plant or facility prior to use, or certaincomponents of the fluid can be pre-mixed prior to use and thentransported to the job site. Certain components of the fluid may beprovided as a “dry mix” to be combined with fluid or other componentsprior to or during introducing the fluid into the well.

If the fluid is being transported to the well-site, preferably thecomponents for a treatment fluid according to the disclosure should notbe allowed to freeze or be exposed to temperatures in excess of 120° F.for extended periods of time.

In certain embodiments, the preparation of a fluid can be done at thejob site in a method characterized as being performed “on the fly.” Theterm “on-the-fly” is used herein to include methods of combining two ormore components wherein a flowing stream of one element is continuouslyintroduced into flowing stream of another component so that the streamsare combined and mixed while continuing to flow as a single stream aspart of the on-going treatment. Such mixing can also be described as“real-time” mixing.

Conventional mixing equipment, such as a batch mixer or cementingequipment may be used.

If desired, the components can be introduced as separate treatmentfluids and mixed downhole. The separate treatment fluids with thedifferent components can be separated, for example, by water-basedspacer or plugs.

The rheology, sag, and settling expectations in the fluid may vary basedon formulation and temperature. Once mixed, time, temperature, and thedegree of reaction influence setting time and the physical properties ofa set material formed by the treatment fluid.

Conventional pre-job cement modeling estimations can be applied to thisfluid.

Equipment in the well should be cleaned after exposure to the treatmentfluid or its components. Certain downhole equipment, such as tools withmovable parts, floats, or roller-cone drill bits may be adverselyaffected by a treatment fluid according to the disclosure if allowed toset near the equipment or it is not cleaned after use.

The equipment used in a treatment involving a treatment fluid accordingto the disclosure or its components can be cleaned by flushing andrinsing with a suitable solvent, for example, a mutual solvent such asMusol A.

Introducing Into Well or Zone

Often the step of delivering a fluid into a well is within a relativelyshort period after forming the fluid, for example, less within 30minutes to one hour. More preferably, the step of delivering the fluidis immediately after the step of forming the fluid, which is “on thefly.”

It should be understood that the step of delivering a fluid into a wellcan advantageously include the use of one or more fluid pumps.

Introducing Below Fracture Pressure

In an embodiment, the step of introducing is at a rate and pressurebelow the fracture pressure of the treatment zone.

Allowing Time for Curing of Resin in the Well

After the step of introducing a treatment fluid according to thedisclosure, it is usually desirable to allow for curing of the resincomposition in the well. This preferably occurs with time under theconditions in the zone of the subterranean fluid.

Returned Fluid Disposal

In an embodiment, any unused treatment fluid, or returned treatment, orcomponents thereof should be collected for disposal, for example, in anopen-top tank.

Hole Clean Out

If required, any hole that may need to be cleaned out as a result of atreatment fluid forming a solid barrier or plug according to thedisclosure would need to be drilled out. It can form a permanentbarrier, such that drilling would be required for its removal.

Producing Hydrocarbon from Subterranean Formation

In some embodiments, after such use of a fluid according to thedisclosure, a step of producing hydrocarbon from the well or aparticular zone may be a desirable objective.

Applications

Generally, the treatment fluids of the present disclosure may be usedfor any purpose. In some embodiments, the treatment fluid may be used toservice a well bore that penetrates a subterranean formation.

Servicing a well bore includes, without limitation, positioning thetreatment fluid in the well bore to isolate the subterranean formationfrom a portion of the well bore; to support a conduit in the well bore;to plug a void or crack in the conduit; to plug a void or crack in acement sheath disposed in an annulus of the well bore; to plug aperforation; to plug an opening between the cement sheath and theconduit; to prevent the loss of aqueous or nonaqueous drilling fluidsinto loss circulation zones such as a void, vugular zone, or fracture;to plug a well for abandonment purposes; a temporary plug to diverttreatment fluids; as a chemical packer to be used as a fluid in front ofcement slurry in cementing operations; and to seal an annulus betweenthe well bore and an expandable pipe or pipe string. For instance, thetreatment fluid may withstand substantial amounts of pressure, forexample, the hydrostatic pressure of a drilling fluid or cement slurry,without being dislodged or extruded. The treatment fluid may form anon-flowing, intact mass. This mass plugs the zone and inhibits loss ofsubsequently pumped drilling fluid, which allows for further drilling.

In some embodiments, the treatment fluids may be placed into an annulusof the well bore and allowed to set such that it isolates thesubterranean formation from a different portion of the well bore. Thetreatment fluids may thus form a barrier that prevents fluids in thatsubterranean formation from migrating into other subterraneanformations. Within the annulus, the fluid also serves to support aconduit, for example, casing, in the well bore.

In other embodiments, the treatment fluid may be positioned in a wellbore in a multilateral well bore configuration including at least twoprincipal well bores connected by one or more ancillary well bores.

In secondary cementing, often referred to as squeeze cementing, thetreatment fluid may be strategically positioned in the well bore to pluga void or crack in the conduit, to plug a void or crack in the hardenedsealant (for example, cement sheath) residing in the annulus, to plug arelatively small opening known as a microannulus between the hardenedsealant and the conduit, and so forth, thus acting as a sealantcomposition.

In some embodiments, the treatment fluids according to the disclosuremay be used in primary cementing operations, to cement a pipe string(for example, casing, liners, expandable tubulars, etc.) in place. Insuch a primary cementing operation, treatment fluid may be pumped intoan annulus between the walls of the well bore and the exterior surfaceof the pipe string disposed therein. The treatment fluid may set in theannular space, thereby forming an annular sheath of hardened,substantially impermeable resin that may support and position the pipestring in the well bore and may bond the exterior surface of the pipestring to the subterranean formation. Among other things, the sheathsurrounding the pipe string may function to prevent the migration offluids in the annulus, as well as protecting the pipe string fromcorrosion.

Generally, the treatment fluids of the present disclosure may beintroduced into a well bore using any suitable technique. For example,in some embodiments of the present disclosure, treatment fluids may beintroduced into a well bore by drilling an interception well bore to“intercept” an existing well bore. Once communication with the existingwell is established, the treatment fluid of the present disclosure maythen be pumped into the well bore as is known in the art. However, ifcommunication cannot be established, the treatment fluid may still beintroduced into the existing well bore by “lubricating” the existingwell bore. In this process, the treatment fluid may be injected into theexisting well bore even though communication has not been established.This results in the compression of the fluids and material inside thewell bore. Once the composition has been introduced into the well boreto be serviced, the buoyancy, density, or specific gravity of theweighting material in the composition may be used to facilitate theplacement of the composition into a desired location within the wellbore.

In an embodiment, the treatment fluid can be used as a chemical packer.

CONCLUSION

Therefore, the present disclosure is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein.

The exemplary fluids disclosed herein may directly or indirectly affectone or more components or pieces of equipment associated with thepreparation, delivery, recapture, recycling, reuse, or disposal of thedisclosed fluids. For example, the disclosed fluids may directly orindirectly affect one or more mixers, related mixing equipment, mudpits, storage facilities or units, fluid separators, heat exchangers,sensors, gauges, pumps, compressors, and the like used generate, store,monitor, regulate, or recondition the exemplary fluids. The disclosedfluids may also directly or indirectly affect any transport or deliveryequipment used to convey the fluids to a well site or downhole such as,for example, any transport vessels, conduits, pipelines, trucks,tubulars, or pipes used to fluidically move the fluids from one locationto another, any pumps, compressors, or motors (for example, topside ordownhole) used to drive the fluids into motion, any valves or relatedjoints used to regulate the pressure or flow rate of the fluids, and anysensors (i.e., pressure and temperature), gauges, or combinationsthereof, and the like. The disclosed fluids may also directly orindirectly affect the various downhole equipment and tools that may comeinto contact with the chemicals/fluids such as, but not limited to,drill string, coiled tubing, drill pipe, drill collars, mud motors,downhole motors or pumps, floats, MWD/LWD tools and related telemetryequipment, drill bits (including roller cone, PDC, natural diamond, holeopeners, reamers, and coring bits), sensors or distributed sensors,downhole heat exchangers, valves and corresponding actuation devices,tool seals, packers and other wellbore isolation devices or components,and the like.

The particular embodiments disclosed above are illustrative only, as thepresent disclosure may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. It is, therefore, evident that theparticular illustrative embodiments disclosed above may be altered ormodified and all such variations are considered within the scope of thepresent disclosure.

The various elements or steps according to the disclosed elements orsteps can be combined advantageously or practiced together in variouscombinations or sub-combinations of elements or sequences of steps toincrease the efficiency and benefits that can be obtained from thedisclosure.

It will be appreciated that one or more of the above embodiments may becombined with one or more of the other embodiments, unless explicitlystated otherwise.

The illustrative disclosure can be practiced in the absence of anyelement or step that is not specifically disclosed or claimed.

Furthermore, no limitations are intended to the details of construction,composition, design, or steps herein shown, other than as described inthe claims.

What is claimed is:
 1. A fluid composition comprising: (A) a liquidhardenable resin component comprising an epoxy resin; (B) a hardeningagent component comprising a hardening agent for the epoxy resin; and(C) an impact modifier component comprising an impact modifier selectedto impart an increased impact resistance after hardening of the epoxyresin.
 2. The composition according to claim 2, wherein the epoxy resincomprises a diglycidyl ether functionalized molecule or amultifunctional glycidyl ether molecule.
 3. The composition according toclaim 2, wherein the diglycidyl ether is selected from the groupconsisting of: a diglycidyl ether of bisphenol A, optionally blendedwith butyl glycidyl ether, cyclohexane dimethanol diglycidyl ether, andany combination thereof.
 4. The composition according to claim 1,wherein the hardening agent is selected from the group consisting of:aliphatic amines, aliphatic tertiary amines, aromatic amines,cycloaliphatic amines, heterocyclic amines, amido amines, polyamides,polyethyl amines, polyether amines, polyoxyalkylene amines, carboxylicanhydrides, triethylenetetraamine, ethylene diamine,N-cocoalkyltrimethylene, isophorone diamine, Naminophenyl piperazine,imidazoline, 1,2-diaminocyclohexane, polytheramine,diethyltoluenediamine, 4,4′-diaminodiphenyl methane,methyltetrahydrophthalic anhydride, hexahydrophthalic anhydride, maleicanhydride, polyazelaic polyanhydride, and phthalic anhydride.
 5. Thecomposition according to claim 1, wherein the hardening agent componentcomprises: diethyltoluenediamine.
 6. The composition according to claim1, additionally comprising: an accelerator.
 7. The composition accordingto claim 6, wherein the accelerator comprises a tertiary amine.
 8. Thecomposition according to claim 6, wherein the accelerator comprises:2,4,6 tridimethylaminomethylphenol.
 9. The composition according toclaim 1, wherein the impact modifier comprises a polyethyleneglycol orpolypropylene having a functionality selected from the group consistingof: glycidyl ether, epoxide, carboxylic acid, and anhydride.
 10. Thecomposition according to claim 1, wherein the impact modifier isselected from the group consisting of: polyethyleneglycol diglycidylether, polypropyleneglycol diglycidyl ether, and any combinationthereof.
 11. A method of treating a treatment zone of a well, the methodcomprising: (A) providing a treatment fluid comprising (i) a liquidhardenable resin component comprising an epoxy resin; (ii) a hardeningagent component comprising a hardening agent for the epoxy resin; and(iii) an impact modifier component comprising an impact modifierselected to impart an increased impact resistance after hardening of theepoxy resin; (B) introducing the treatment fluid into a well bore; and(C) allowing the treatment fluid to form a hardened mass the well bore.12. The method according to claim 11, wherein the epoxy resin comprisesa diglycidyl ether functionalized molecule or a multifunctional glycidylether molecule.
 13. The method according to claim 11, wherein thediglycidyl ether is selected from the group consisting of: a diglycidylether of bisphenol A, optionally blended with butyl glycidyl ether,cyclohexane dimethanol diglycidyl ether, and any combination thereof.14. The method according to claim 11, wherein the hardening agent isselected from the group consisting of: aliphatic amines, aliphatictertiary amines, aromatic amines, cycloaliphatic amines, heterocyclicamines, amido amines, polyamides, polyethyl amines, polyether amines,polyoxyalkylene amines, carboxylic anhydrides, triethylenetetraamine,ethylene diamine, N-cocoalkyltrimethylene, isophorone diamine,Naminophenyl piperazine, imidazoline, 1,2-diaminocyclohexane,polytheramine, diethyltoluenediamine, 4,4′-diaminodiphenyl methane,methyltetrahydrophthalic anhydride, hexahydrophthalic anhydride, maleicanhydride, polyazelaic polyanhydride, and phthalic anhydride.
 15. Themethod according to claim 11, wherein the hardening agent componentcomprises: diethyltoluenediamine.
 16. The method according to claim 11,additionally comprising: an accelerator.
 17. (canceled)
 18. The methodaccording to claim 11, wherein the accelerator comprises: 2,4,6tridimethylaminomethylphenol.
 19. The method according to claim 11,wherein the impact modifier comprises a polyethyleneglycol orpolypropylene having a functionality selected from the group consistingof: glycidyl ether, epoxide, carboxylic acid, and anhydride.
 20. Themethod according to claim 11, wherein the impact modifier is selectedfrom the group consisting of: polyethyleneglycol diglycidyl ether,polypropyleneglycol diglycidyl ether, and any combination thereof. 21.The method according to claim 11, wherein the introducing of thetreatment fluid is into an annulus between a tubing string in the wellbore and a subterranean formation; and wherein the allowing thetreatment fluid to form a hardened mass the well bore is within theannulus.